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Collaborating Authors
Results
Abstract Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application. The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation. Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate. Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle. We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
- South America (1.00)
- Asia (1.00)
- Europe > United Kingdom (0.93)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type (0.68)
- Geology > Mineral > Silicate > Phyllosilicate (0.68)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- (6 more...)
Estimation of Capillary Pressure and Relative Permeability from Downhole Advanced Wireline Measurements for Waterflooding Design
Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company) | Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Kalawina, Mahmoud (Halliburton) | Hashmi, Gibran (Halliburton) | Hamza, Farrukh (Halliburton) | Ramakrishna, Sandeep (Halliburton)
Abstract Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations. The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.
- Europe (1.00)
- North America > United States > Texas (0.95)
- North America > United States > California (0.68)
- Asia > Middle East > Kuwait > Ahmadi Governorate (0.29)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (17 more...)
An Experimental Study of Enhanced Oil Recovery EOR Using a Green Nano-Suspension
Wei, Bing (Southwest Petroleum University) | Qinzhi, Li (Southwest Petroleum University) | Wang, Yanyuan (Southwest Petroleum University) | Gao, Ke (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Sun, Lin (Southwest Petroleum University)
Abstract In this work, a novel nano-suspension (NS), which was mainly composed of a surface functionalized nano-cellulose, was successfully developed for "green" chemical EOR use. The rheological analysis indicated that this NS was a pseudo-plastic (shear-thinning) fluid and presented noticeable viscoelasticity. The oil displacement behaviors of this NS were thoroughly examined using core flooding methods. The EOR efficiency dependence of the NS on permeability, oil viscosity and injected volume was included. The experimental results showed that the NS flooding (NSF) further improved the oil recovery by 3-17% on the basis of water flooding. Furthermore, micro flow tests were conducted in a visual micro-model to study its flow behaviors in porous media and EOR mechanisms. Through the micro-model, the displacement behaviors and mechanisms including emulsification, dragging/squeezing and wettability alteration, were visually observed. These properties promise this NS as a green displacement agent for chemical EOR.
- Asia > China (0.47)
- North America > United States (0.47)
Abstract During an Alkaline-Surfactant-Polymer (ASP) flood in reservoir rock, often an in situ microemulsion phase forms upon contact of the injected ASP fluid with the residing oil. These microemulsions form as a result of the required ultra-low interfacial tensions (IFT) for oil mobilization and displacement of the residual oil, but they can have a high viscosity. The success of an ASP flood on oil recovery depends on the complex flow of the injected ASP solution, the mobilized oil and the in situ microemulsion phase, which the latter often has a higher shear-dependent viscosity than the other two. In this study, steady-state (SS) corefloods have been performed to investigate the in situ microemulsion formation and rheology during the multiphase flow. The aqueous phase, namely brine, AS or ASP, was co-injected with n-decane or reservoir ‘dead’ crude in Berea outcrop cores for a range of fractional flow ratios. The pressure differential was continuously recorded, and was then converted in an apparent, in situ, viscosity value. For this stage of the project the water and oil phase saturations in the plugs were not yet measured. For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points. It is anticipated that this study leads to a fast and fit for purpose characterization method of ASP-crude oil systems that provides data in a form, such as relative permeability data and residual oil saturation that can be applied directly in reservoir simulators.
- Europe (0.68)
- North America > United States > Texas (0.28)
Investigation and Interpretation of a Novel Surfactant-Polymer Approach to Increase Extra-Heavy Oil Recovery: Application to a Thin-Bedded Reservoir, Faja Petrolifera Del Orinoco, Venezuela.
Rodriguez, F.. (PDVSA, IFP Energies nouvelles, Paris Diderot University) | Rousseau, D.. (IFP Energies nouvelles) | Bekri, S.. (IFP Energies nouvelles) | Hocine, S.. (Solvay) | Degre, G.. (Solvay) | Djabourov, M.. (ESPCI Paris Tech) | Bejarano, C. A. (PDVSA)
Abstract Primary cold production for the extra-heavy oils (4–10°API) of La Faja Petrolifera del Orinoco (FPO), Venezuela, is currently a low percentage (<5%) of the OOIP. Chemical EOR (CEOR) studies are being accomplished in order to increase oil recovery in those thin-bedded reservoirs which host up to 35% of the OOIP, where thermal EOR methods are not convenient because of heat losses and environmental issues. Specifically, Surfactant-Polymer (SP) flooding is now considered as a feasible approach to achieve both mobility control and mobilization of residual oil in the FPO's target zones for CEOR. The objectives of this experimental study were to identify some mechanisms in play when surfactant and polymer solutions are injected in cores to displace extra-heavy oil and to assess for the potential of SP flooding for one of the FPO's reservoirs. The tests reported were performed with a dead crude oil of 9°API and 4500 cP, and injection water salinity of 6.4 g/L with low hardness and at a temperature of 50°C. The SP formulation consisted of a standard high molecular weight HPAM at rather high concentration to achieve high viscosity and an alkaline-free surfactant formulation providing both low interfacial tension (IFT) and good compatibility with polymer even at high polymer concentration. When possible, oil saturation profiles were determined by CT-scan at the main steps of the experiments. Conditions and methodologies to determine the relevant experimental parameters for high viscosity oil have firstly been developed. Then, a set of surfactant and polymer injection tests have been performed on Bentheimer outcrop cores. These tests demonstrated that injection of the SP formulation after a secondary polymer flood was able to achieve a significant reduction of the residual oil (ASo = 80% ROIP). Results of secondary injections of water (final oil saturation, Sofinal = 63%), surfactant solution (Sofinal = 39%) and SP formulation (Sofinal = 5%) have also shown that mobility control is of tremendous importance to achieve high recovery, even at the core-scale. The potential of the SP formulation has also been validated on unconsolidated reservoir rock material from the FPO (Sofinal = 8%). Relative permeabilities have also been determined to investigate the feasibility of an effective modeling of the impact of the surfactant on oil recovery without making any assumption of the local mechanisms in play. Future work will involve 3D reservoir simulation with physico-chemical parameters generated at the lab.
- Europe (1.00)
- Asia > Middle East (1.00)
- Africa (1.00)
- (2 more...)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Zuata Field (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Oficina Formation (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Hamaca Area > Bare Field (0.99)
- (2 more...)
Abstract MEOR (microbial enhanced oil recovery) is known as one of the emerging low-cost EOR technologies, which uses in-situ microorganisms living in the oil field. Some of the most promising microbial-induced mechanisms include production of extracellular polymeric sugars (EPS), biofilms as well as selective plugging caused by cell growth. However, there is limited data available concerning the way microbes and biofilms behave in contact to surfaces in porous media in the context of MEOR. The aim of this work was to investigate bacterial growth and biofilm production in the framework of an ongoing MEOR project conducted by Wintershall and BASF. We used various approaches to investigate cell behavior of a halophilic bacterial community derived from a Wintershall oil field. Bacterial growth was conducted in both batch cultures and under dynamic conditions. To visualize cell adhesion and also exopolymers occuring in biofilms we used specific fluorescent dyes. During incubation of the microbes over several weeks we could visualize different types of EPS under the microscope. This observation fits perfectly to a concurrent viscosity increase of the surrounding media. Modelling approaches were applied to estimate the potential contribution of these effects on additional oil recovery. The observations including cell clumping, sorption and polymer production were geometrically quantified and the effect of the modifications on permeability profile and resulting flow characteristics was numerically investigated with fluid dynamic simulations of the petrophysical changes. The potential implications of the observed changes on EOR capability by conformance control and wettability modification were further estimated with analytical approaches. With the developed methods for visualization and modelling of the microbes and biofilms in both batch and dynamic conditions, we are able to monitor the clumping and sorption behavior of the cells, which will help to interprete data obtained during an upcoming MEOR field trial.
- North America > United States (0.47)
- Europe (0.28)
- Geology > Mineral (0.68)
- Geology > Geological Subdiscipline (0.46)
Scaling of Low IFT Imbibition in Oil-Wet Carbonates
Li, Yuxiang (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Churchwell, Lauren (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.
- Geology > Rock Type > Sedimentary Rock (0.70)
- Geology > Mineral (0.49)
- Geology > Geological Subdiscipline (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Research and Application of Micron-Size Polyacrylamide Elastic Microspheres as a Smart Sweep Improvement and Profile Modification Agent
Yao, Chuanjin (China University of Petroleum) | Xu, Xiaohong (China University of Petroleum) | Wang, Dan (China University of Petroleum) | Lei, Guanglun (China University of Petroleum) | Xue, Shifeng (China University of Petroleum) | Hou, Jian (China University of Petroleum) | Cathles, Lawrence M. (Cornell University) | Steenhuis, Tammo S. (Cornell University)
Abstract Micron-size polyacrylamide elastic microspheres (MPEMs) are a smart sweep improvement and profile modification agent, which can be prepared controllably on the ground through inverse suspension polymerization using acrylamide crosslinked with an organic crosslinker. MPEMs can tolerate high temperature of 90 °C, high salinity of 20000 mg/L and wide pH value range of 4.0–10.3. MPEMs suspension almost has no corrosion effect on the injection pipeline and equipment. MPEMs can suspend in produced water easily and be pumped into formation at any rate. More importantly, MPEMs can reach the designed size after hydration swelling in oil formation and a reliable blockage can be formed; MPEMs can deform elastically and move forward step by step to realize a moveable sweep improvement and profile modification process in reservoirs. The pore-scale visualization experiment shows that there are four migration patterns for MPEMs transport in porous media and they are smooth passing, elastic plugging, bridge plugging and complete plugging. MPEMs can deform depending on their elasticity and pass through these pore-throats. Parallel-sandpack physical modeling experiment under the simulated reservoir conditions shows that MPEMs mainly enter into and plug high permeability layer whose permeability is reduced from 3.642 μm to 0.546 μm, and almost do not clog low-permeability layer whose permeability is reduced from 0.534 μm to 0.512 μm. Field application results of MPEMs treatment in a serious heterogeneous, high temperature and high salinity reservoir show that MPEMs can effectively improve swept volume and displacement efficiency. Because of the excellent properties, MPEMs treatment will become a cost-effective method for sweep improvement and profile modification to serious heterogeneous, high temperature and high salinity reservoirs with fractures and channels.
- Asia > China (1.00)
- North America > United States (0.69)
- South America > Venezuela > Lake Maracaibo > Maracaibo Basin > Lagomar Field (0.99)
- Asia > China > Tianjin > Bohai Basin > Huanghua Basin > Dagang Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- (3 more...)
Experimental Study on Calculating Capillary Pressure from Resistivity
Hou, Binchi (Research Institute of Shaanxi Yanchang Petroleum (Group) CO., LTD.) | Liu, Hongliang (China Petroleum Logging TuHa Business Division) | Bian, Huiyuan (Xi'an University of Science and Technology) | Wang, Chengrong (China Petroleum Logging TuHa Business Division) | Xie, Ronghua (Daqing Oilfield CO.LTD., PetroChina) | Li, Kewen (China University of Geosciences(Beijing)/Stanford University)
Abstract Capillary pressure and resistivity in porous rocks are both functions of wetting phase saturation. Theoretically, there should be a relationship between the two parameters. However, few studies have been made regarding this issue. Capillary pressure may be neglected in high permeability reservoirs but not in low permeability reservoirs. It is more difficult to measure capillary pressure than resistivity. It would be useful to infer capillary pressure from resistivity well logging data if a reliable relationship between capillary pressure and resistivity can be found. To confirm the previous study of a power law correlation between capillary pressure and resistivity index and develop a mathematical model with a better accuracy, a series of experiments for simultaneously measuring gas-water capillary pressure and resistivity data at a room temperature in 16 core samples from 2 wells in an oil reservoir were conducted. The permeability of the core samples ranged from 9 to 974 md. The gas-water capillary pressure data were measured with confining pressures using a semi-porous plate technique. We developed the specific experimental apparatus to measure gas-water capillary pressure and resistivity simultaneously. The results demonstrated that the previous power law model correlating capillary pressure and resistivity works well in many cases studied. A more general relationship between the exponent of the power law model and the rock permeability was developed and verified using the experimental data.
- Asia > China (1.00)
- North America > United States > Texas (0.29)
- Research Report > New Finding (0.65)
- Research Report > Experimental Study (0.41)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements. Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil. DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation. In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (RRF) of both water and oil phases regardless the core's wetting conditions; the DPR effectiveness was more pronounced in oil-wet cores than in water-wet ones.
- Europe (1.00)
- North America > United States > Texas (0.46)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Statfjord Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Dunlin Group Formation (0.99)
- (4 more...)